A large fraction of the world's total natural gas reserves requires treating before it can be transported or used as feed stock or fuel gas. The presence of hydrogen sulfide is problematic as it is both highly toxic and tends to embrittle steel pipelines. The presence of water can present transportation problems and in combination with carbon dioxide, lead to corrosion issues. The presence of heavy hydrocarbons can result in condensation issues and a too high heating value. Other natural gas reserves are poor in quality because the methane and other combustible gas components are diluted with non-combustible carbon dioxide and nitrogen gas, making the unrefined gas a relatively low Btu fuel source.
If the natural gas deposits contain high percentages of carbon dioxide and hydrogen sulfide, the gas is considered both poor and sour. In order to provide usable natural gas, it is known to remove the carbon dioxide and hydrogen sulfide by membrane or absorption processes. The natural gas intended to be treated by means of the method according to the invention may be saturated with water and hydrocarbons. This natural gas is generally at the pressure and at the temperature of the production well or of any process used upstream.
Natural gas usually contains a significant amount of carbon dioxide. The proportion of carbon dioxide can range up to 70% by mole or higher, often from 5 to 40% by mole. A typical sour natural gas can, for example, contain 50 to 70% by mole of methane, 2 to 10% by mole of ethane, 0 to 5% by mole of propane, 0 to 20% by mole of hydrogen sulfide and 0 to 30% by mole of carbon dioxide. By way of example, the natural gas to be treated can contain 70% by mole of methane, 2% by mole of ethane, 0.7% by mole of propane, 0.2% by mole of butane, 0.7% by mole of hydrocarbons with more than four carbon atoms, 0.3% by mole of water, 25% by mole of carbon dioxide, 0.1% by mole of hydrogen sulfide and various other compounds as traces.
There are a number of different methods that have been used to treat natural gas streams. In most methods, a combination of technologies is employed to remove condensable components as well as gaseous components such as carbon dioxide. In one process, adsorbents are used to remove heavy hydrocarbons. In another process refrigeration is used to remove heavy hydrocarbons. In yet another process an amine solvent is used to remove carbon dioxide and hydrogen sulfide. Another particularly useful method involves permeable membrane processes and systems that are known in the art and have been employed or considered for a wide variety of gas and liquid separations. In such operations, a feed stream is brought into contact with the surface of a membrane, and the more readily permeable component of the feed stream is recovered as a permeate stream, with the less-readily permeable component being withdrawn from the membrane system as a non-permeate stream.
Membranes are widely used to separate permeable components from gaseous feed streams. Examples of such process applications include removal of acid gases from natural gas streams, removal of water vapor from air and light hydrocarbon streams, and removal of hydrogen from heavier hydrocarbon streams. Membranes are also employed in gas processing applications to remove permeable components from a process gas stream.
Membranes for gas processing typically operate in a continuous manner, wherein a feed gas stream is introduced to the membrane gas separation module on a non-permeate side of a membrane. In most natural gas membrane applications, the feed gas is introduced at separation conditions which include a separation pressure and temperature which retains the components of the feed gas stream in the vapor phase, well above the dew point of the gas stream, or the temperature and pressure condition at which condensation of one of the components might occur. The feed gas stream fed to the gas separation membrane may contain a substantial amount of moisture and condensable hydrocarbons. These condensable components can cause problems in downstream equipment, such as condensation in the membrane elements, thereby causing membrane swelling, or coating of the membrane surface, leading to decreased permeability. In order to compensate for the performance reduction caused by condensation of the feed gas stream during the lifetime of a membrane system, such membrane systems are often oversized to compensate for the loss of membrane surface over the useful life of the membrane. However, for high volume gas treating application, this over design of membrane capacity can be very costly, increasing the cost of a membrane system.
In order to provide optimal conditions for membrane operation and extend the membrane life, various processes pretreat the natural gas prior to sending it to the gas separation membrane. One such pretreatment process uses a thermal swing adsorption (TSA). These TSA units use aluminosilicate type adsorbents to remove heavier hydrocarbons and water from the natural gas. Additionally, mercury and other contaminants can be removed with such a pretreatment unit too. This pretreatment prevents condensation in the membrane process and the subsequent coating of the membrane surface with heavy hydrocarbons, thereby extending membrane life. The removal of components in the pretreatment may also contribute in meeting the downstream product specification of the natural gas stream.
In order to control the size of the pretreatment unit, the temperature of the wet feed gas entering the pretreatment unit is typically first cooled from, for example, between 40 to 45° C. (104 to 113° F.) down to about 15 to 20° C. (59 to 68° F.) (which is 5° C. (9° F.) above the hydrate formation temperature associated with the hydrocarbons) to allow liquid water and hydrocarbons to be separated from the gas stream that is routed to the TSA unit. If the wet feed stream is cooled to the hydrate formation temperature, hydrates may form in the heat exchanger and foul same or damage downstream equipment. The cooling may be accomplished by externally chilling the wet feed gas, or by exchanging heat between the wet feed gas and other gas streams, or by a combination of the two. As will be appreciated the use of external chilling requires equipment and increases the operating cost for a processor. Additionally, the limit of the hydrate formation temperature has been a limit to the existing streams that have typically been cross exchanged with the wet gas feed.
Therefore, it would be desirable for one or more effective and efficient processes that utilize existing low temperature gas streams to cool a feed gas to a membrane guard unit.